1. Field of the Invention
The invention relates to underground media development. In particular, the invention relates to a method of monitoring an underground formation wherein either gas is injected, for example, for monitoring of a geological gas storage site or gas is extracted, for example, from the underground formation within hydrocarbon production.
2. Description of the Prior Art
Responsible and efficient monitoring of an underground storage site for example for gas, carbon dioxide after capture, requires good knowledge of the spatial distribution of the gas, and of the evolution of distribution over time. Drilling wells is a good way to learn what is in the subsoil but, is costly and the question about what there is left in the subsoil remains. Seismic imaging provides information distributed over the entire explored three-dimensional zone, even though its spatial resolution is limited. Seismic prospecting sends waves into the subsoil from various shotpoints and uses many receivers, to record the echoes reflected back by the boundaries between the geological layers.
If gas is injected into a reservoir, the acoustic impedance thereof, which is the product of the speed of sound by the density, decreases and the echoes are modified. All the impedances are expressed in (m/s)·(g·cm3) in the description. Whether gas storage is temporary, as for natural gas, or definitive, as for carbon dioxide, seismic imaging thus is a candidate for monitoring the gas, whether it spreads through the reservoir, undergoes a chemical transformation or even possibly leaks to the surface.
Seismic prospecting can be performed almost everywhere on Earth including onshore as well as offshore. Historically, seismic data have been acquired for a long time along rectilinear 2D profiles. Today, 3D acquisitions are predominant and allow three-dimensional imaging of the subsoil at increasingly great depths. Large hydrocarbon reservoirs have been recently discovered as deep as between 5 km and 7 km.
Onshore, the seismic wave source can be an explosive buried in a wellbore at a depth of meters or decameters. But most frequently a vibrator in a heavy truck provided with a solid metal plate under the truck is raised to allow displacement of the vehicle, but on which it lifts and rests with all its weight when it is about to emit. The truck is then made to oscillate on its plate by jacks, which sends waves into the ground. Unlike explosives, the vibrator cannot send short impulses. The shortness of the wave conditions the resolution of the resulting images. Facing the same problem as radars: it is not possible to emit a signal that is both very brief and very energetic. The vibrator solves the problem according to the same principle by emitting a frequency-modulated signal whose duration, of the order of one minute for the vibrator, allows sending a high-energy wave. To recover the shortness of the wave, the emitted wave train is designed in such a way that its autocorrelation is as short as possible, and the crosscorrelation of the seismic records with the emitted wave train provides records close to those provided by an impulse source. The frequency band of the emitted signals is variable according to the depth of the target and to the nature of the subsoil to roughly range between 10 and 100 Hz. The echoes reflected by the mechanical property discontinuities of the formations are converted to electrical signals by thousands of pickups referred to as geophones, which are distributed around the source ranging from hectometers to kilometers. These records are then conveyed by radio to a truck which is referred to as the lab where they are transferred to a hard disk.
Offshore, a boat tows several arrays of air guns immersed to a depth of meters. These arrays are carried off course by hydrodynamic devices with respect to the boat trajectory, which allows their alignment across this trajectory. Each air gun array works in turn, with one shot every five to ten seconds. Furthermore, the boat tows streamers which are kilometers in length parallel to the boat trajectory and arranged at regular intervals. The boat can also be assisted by two other boats with one on each side to provide, for example, for so-called wide-azimuth acquisitions in order to better visualize beneath salt domes in the Gulf of Mexico. Towed at a depth of meters, these streamers are plastic tubes which are centimeters in diameter and contain a metallic cable for tensile strength. Pressure detectors, referred to as hydrophones, convert the waves into electrical signals. Electrical wires transmit these signals to the boat and a filling liquid of selected density is provided in the streamers so that they neither float nor sink. In order to counter the effect of the marine currents, an acoustical system measures permanent defects of the geometry of the device and drives deflectors that correct them.
After acquisition, the data are processed to form images of the subsoil. A segment that connects the point-source to the point-receiver, whose middle is called the “midpoint” and whose length is called the “offset”, corresponds to each record. A grid map of the studied zone is defined and the records are grouped together into collections whose midpoints share the same square in the grid. Individual records are often being affected by noise and are added up so that the signal will increase in n, the number of signals stacked, and the noise in root of n, which improves the signal-to-noise ratio. A velocity analysis determines the dynamic corrections that will compensate for the additional path travelled by the waves whose emission and reception points are distant. After applying these dynamic corrections, common-depth-point stacking is performed. Although the simplistic hypotheses of common-depth-point shooting are often grossly at fault (piedmonts, salt domes), it is systematically performed. Common-depth-point shooting provides images by the artifice that the stacked record corresponding to each midpoint is associated therewith and the time axis being oriented downward. The drawback of this image is that it is not geometrically correct. The images are in fact identical and the thicknesses of two layers may seem distinct because their velocities are different. Furthermore, if the layers are inclined, the point where the reflection occurs is arbitrarily brought to the vertical of the midpoint, which is groundless. In order to overcome these drawbacks, a processing method referred to as “migration”, which has many variants, is used. Time migrations keep time as the vertical coordinate which is unlike depth migrations. When the wave propagation is complicated, the common-depth-point shooting hypotheses are not viable and pre-stack migration is preferred to post-stack migration. All the migrations require knowledge of the velocity field, but this requirement is critical for depth migration.
Stratigraphic inversion is a known process which is practiced as a computer implemented process, provides better knowledge of the reservoir and converts the seismic image where the reflections indicate impedance contrasts to a three-dimensional map of the acoustic impedance itself and provides valuable information on the nature of the rocks.
Stratigraphic inversion comprises three stages. The first stage is well-to-seismic calibration, whose goal is to identify the wave train, referred to as “wavelet”, that has propagated in the subsoil. The impedance log is therefore calculated from sonic logs (sound velocity) and density logs, and a low-pass filter is applied thereto in order to bring it into the seismic frequency band. The reflection coefficient sequence is deduced from this impedance log, and eventually the wavelet by comparison with the well seismic (common-depth-point data, often time migrated). The second stage is the construction of the a priori model, whose goal is to make up for the lack of very low frequencies in the seismic method. Horizons picked on the seismic therefore determine several units are defined on which laminations whose laminae are the deposition isochrones. Each lamination allows interpolation of the impedances known for the wells at any point of the corresponding unit. For each unit, the lamination is defined according to three options: parallel to the upper horizon, to the lower horizon, or conformable. Velocity analyses may be used to make up for the lack of well data, but then density values are required. The third stage is inversion proper, which finds the impedance field that minimizes the sum of two functionals. The first one, referred to as “seismic functional”, measures the norm L2 difference between the seismic calculated on the current impedance and the observed seismic. The second one, referred to as “geological functional”, measures the difference between the current impedance and the a priori impedance. This geological functional is decomposed into two terms, a norm L2 on the difference between the calculated and a priori impedances, and a norm L2 on the gradient of this difference after projection of this gradient on the plane tangential to the local lamina of the lamination. Equation (1) makes this functional explicit:F(I)=p1∥w*R(I)−S0∥L2+p2∥I−I0∥L2+p3∥PT(∇(I−I0)∥L2,  (1)where I designates the impedance field, p1 the weight of the seismic functional that depends on the noise-to-signal ratio, w the estimated wavelet upon well-to-seismic calibration, R(I) the reflection coefficient field calculated on the impedance field I, * the convolution, S0 the observed seismic, p2 the weight of sub-term L2 on the difference with the a priori impedance I, and p3 the weight of sub-term L2 on the gradient of the difference with the a priori impedance. It can be noted that since the a priori model is generally smooth, a gradient term in the functional tends to smooth the result, which is not desirable because the vertical resolution is valuable, which is why the gradient is projected (PT in Equation (1)) onto a plane tangential to the local lamina of the sedimentary lamination. This global functional is minimized by a conjugate gradient. This stratigraphic inversion has been patented in French Patent 2,765,692.
A first stratigraphic inversion variant is pre-stack stratigraphic inversion. The datum is no longer only the common-depth-point datum, but a set of several (in practice, three to five) partial stacks wherein the records are sorted out in angle classes according to the angle of incidence upon reflection. Unlike fluids where only one wave type is propagated, two wave types are propagated in the elastic solids of the rocks which are the P waves that arrive first and the S waves that arrive second. P waves are compressional-dilatational waves, like acoustic waves in fluids, that is the direction of vibration of the matter upon passage of the wave is parallel to the direction of propagation of the wave. S waves are shear waves where the direction of vibration is transverse to the direction of propagation. The value of pre-stack stratigraphic inversion is that the dependence of the reflection coefficients as a function of the angle of incidence allows determination not only of the P impedance, but also the S impedance, the product of velocity S by the density, and to a lesser extent the density itself. The pre-stack stratigraphic inversion is disclosed in French Patent 2,800,473.
A second stratigraphic inversion variant is the inversion of multi-component data. In a homogeneous or normal incidence medium, the P waves are transmitted or reflected as P and the S waves as S. In the case of oblique incidence on an interface, the P or S wave is converted into two reflected waves, a P and an S wave, and two transmitted waves, P and S. Onshore, three-component (3C) geophones allow simultaneous recording of the PP waves (P in the forward path and P in the return path) and the PS waves (P in the forward path and S in the return path), which are then separated by processing by their different polarization (direction of vibration). Offshore, recording of PS waves is impossible because the S wave is converted to a weak P wave in the water, unless 3C geophones are installed on the seabed (with OBCs for example). The use of S waves is described in French Patents 2,800,473 and 2,873,823.
A third variant relates to anisotropic stratigraphic inversion. Typically, when the layers are fractured in a certain direction, the seismic waves, whose wavelengths are much greater than the mean distance between fractures, travel through a homogeneous but anisotropic medium. In this case, the offset, which is usually the source-receiver distance, becomes a horizontal vector with a length and an azimuth. The stratigraphic inversion itself becomes azimuth-dependent and its results provide information on the orientation of the fractures, at least when a family of fractures clearly dominates the others.
A fourth variant relates to monitoring of a gas storage site whose evolution over time is followed by seismic acquisitions that are staggered over time. For the sake of simplicity, two periods before and after injection (it could also be withdrawal) are discussed but what follows can apply to three periods or more. The first stage carries out a stratigraphic inversion for each period. In the second stage, law t2(t1) is determined with t1 being the seismic time of any horizon at period 1, and t2 being the time of the same event at period 2. This is referred to as warping, which is compensating for the fact that the fluid change modifies the velocity of the rocks, and therefore the time of the reflections. The third stage carries out a joint inversion of the data of the two periods. The fact that the result in the layers where it is known that there is no gas is constrained by two seismic steps instead of one makes it more reliable and reinforces, as an indirect consequence, the result in the gas zone. This technique is described in French Patent 2,933,499.
If gas is injected into a reservoir, then its acoustic impedance, that is the product of the speed of sound by density, decreases and the echoes are modified. Whether this gas storage is temporary, as for natural gas, or definitive, as for carbon dioxide, seismic imaging thus is candidate for monitoring the history of the gas, whether it spreads through the reservoir, undergoes a chemical transformation or even possibly leaks to the surface.
The seismic frequency band is limited at the top and bottom ends. An impedance decrease in a layer appears in the seismic data, as well as the association of a slight impedance decrease in this layer with a slight increase in the neighboring layers. This “zero mean” effect is harmful to the quantitative estimation of the volume of gas in place because the relation between impedance and saturation is distorted thereby.